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Abstract:

Downhole fluid typing with pulsed neutron logging. A method comprises
obtaining gamma count rates at a particular borehole depth; calculating a
fluid type indicative response value for the borehole depth; determining
at least one fluid type based on the response value for the particular
borehole depth; and producing a display of the at least one fluid type
corresponding to the borehole depth. A system comprises a downhole tool
comprising a neutron source and at least one gamma detector; gamma count
rates produced due to gamma arrivals at the gamma detector(s); and a
processor coupled to a memory, wherein the memory stores a program that,
when executed by the processor, causes the processor to: calculate a
fluid type indicative response value for a particular borehole depth
based on the gamma count rates; and determine at least one fluid type
based on the response value for the particular borehole depth.

Claims:

1. A method comprising: obtaining gamma count rates at a particular
borehole depth; calculating a fluid type indicative response value for
the particular borehole depth; determining at least one fluid type based
on the response value for the particular borehole depth; and producing a
display of the at least one fluid type corresponding to the particular
borehole depth.

2. The method of claim 1, wherein producing the display further comprises
producing a paper plot of the at least one fluid type corresponding to
the particular borehole depth.

9. The method of claim 1, wherein obtaining the at least one gamma decay
curve further comprises operating a neutron source within a borehole.

10. The method of claim 9, wherein operating the neutron source further
comprises operating the neutron source within a cased portion of the
borehole.

11. The method of claim 1, wherein determining the at least one fluid
type further comprises determining the at least one fluid type further
based on a porosity of a formation at the particular borehole depth, and
further based on a pressure in the formation at the particular borehole
depth.

12. A system comprising: a downhole tool comprising a neutron source and
at least one gamma detector; gamma count rates produced due to gamma
arrivals at the at least one gamma detector; a processor coupled to a
memory, wherein the memory stores a program that, when executed by the
processor, causes the processor to: calculate a fluid type indicative
response value for a particular borehole depth based on the gamma count
rates; and determine at least one fluid type based on the response value
for the particular borehole depth.

13. The system of claim 12, wherein the program causes the processor to
calculate the fluid type indicative response value based on the gamma
count rates produced due to the gamma arrivals at multiple gamma
detectors of the downhole tool.

14. The system of claim 12, wherein the program causes the processor to
calculate the fluid type indicative response value as a ratio of
inelastic count rates and capture count rates due to the gamma arrivals
at one gamma detector.

15. The system of claim 12, wherein the program causes the processor to
calculate the fluid type indicative response value as a mathematical
function of the count rates due to the gamma arrivals at one gamma
detector.

16. The system of claim 12, wherein the program causes the processor to
calculate the fluid type indicative response value as a ratio of
inelastic count rates due to the gamma arrivals at multiple gamma
detectors.

17. The system of claim 12, wherein the program causes the processor to
calculate the fluid type indicative response value as a ratio of capture
count rates due to the gamma arrivals at multiple gamma detectors.

18. The system of claim 12, wherein the program causes the processor to
calculate the fluid type indicative response value as a mathematical
function of the count rates due to the gamma arrivals at multiple gamma
detectors.

19. The system of claim 12, wherein the neutron source is positioned
within a cased portion of a borehole.

20. The system of claim 12, wherein the program causes the processor to
determine the at least one fluid type further based on a porosity of a
formation at the particular borehole depth, and further based on a
pressure in the formation at the particular borehole depth.

21. A computer-readable storage media storing a program that, when
executed by a processor, causes the processor to: calculate a fluid type
indicative response value for a particular borehole depth based on the
gamma count rates; and determine at least one fluid type based on the
response value for the particular borehole depth.

22. The computer-readable storage media of claim 21, wherein the program
causes the processor to calculate the fluid type indicative response
value based on the gamma count rates produced due to the gamma arrivals
at multiple gamma detectors of the downhole tool.

23. The computer-readable storage media of claim 21, wherein the program
causes the processor to calculate the fluid type indicative response
value as a ratio of inelastic count rates and capture count rates due to
the gamma arrivals at one gamma detector.

24. The computer-readable storage media of claim 21, wherein the program
causes the processor to calculate the fluid type indicative response
value as a mathematical function of the count rates due to the gamma
arrivals at one gamma detector.

25. The computer-readable storage media of claim 21, wherein the program
causes the processor to calculate the fluid type indicative response
value as a ratio of inelastic count rates due to the gamma arrivals at
multiple gamma detectors.

26. The computer-readable storage media of claim 21, wherein the program
causes the processor to calculate the fluid type indicative response
value as a ratio of capture count rates due to the gamma arrivals at
multiple gamma detectors.

27. The computer-readable storage media of claim 21, wherein the program
causes the processor to calculate the fluid type indicative response
value as a mathematical function of the count rates due to the gamma
arrivals at multiple gamma detectors.

28. The computer-readable storage media of claim 21, wherein the neutron
source is positioned within a cased portion of a borehole.

29. The computer-readable storage media of claim 21, wherein the
processor causes the processor to determine the at least one fluid type
further based on a porosity of a formation at the particular borehole
depth, and further based on a pressure in the formation at the particular
borehole depth.

Description:

CROSS-REFERENCE TO RELATED APPLICATION

[0001] The present application is a national stage application under 35
USC 371 of International Application No. PCT/US09/58521, filed Sep. 28,
2009. The entire disclosure of this prior application is incorporated
herein by this reference.

BACKGROUND

[0002] The present disclosure relates generally to equipment utilized and
operations performed in conjunction with subterranean wells and, in
embodiments described herein, more particularly provides systems and
methods for downhole fluid typing with pulsed neutron logging.

[0003] Well logging is a technique used to identify characteristics of
earth formations surrounding a borehole. The interrogation of a formation
surrounding a borehole to identify one or more characteristics may be by
sound, electrical current, electromagnetic waves, or high energy nuclear
particles (e.g., gamma particles and neutrons). Receiving the
interrogating particle or signal, and determining a formation property
from such particle or signal, is in many cases a complicated endeavor
sometimes involving detecting the interrogating particles or signals at
multiple detectors on a logging tool. Any system or method that enables
precise determination of a formation property provides a competitive
advantage in the marketplace.

NOTATION AND NOMENCLATURE

[0004] Certain terms are used throughout the following description and
claims to refer to particular system components. As one skilled in the
art will appreciate, oilfield service companies may refer to a component
by different names. This document does not intend to distinguish between
components that differ in name but not function.

[0005] In the following discussion and in the claims, the terms
"including" and comprising" are used in an open-ended fashion, and thus
should be interpreted to mean "including, but not limited to . . . ."
Also, the term "couple" or "couples" is intended to mean either an
indirect or direct connection. Thus, if a first device couples to a
second device, that connection may be through a direct connection or
through an indirect connection via other devices and connections.

[0006] "Gamma" or "gammas" shall mean energy created and/or released due
to neutron interaction with atoms, and in particular atomic nuclei, and
shall include such energy whether such energy is considered a particle
(i.e., gamma particle) or a wave (i.e., gamma ray or wave).

[0007] "Gamma count rate decay curve" shall mean, for a particular gamma
detector, a plurality of count values, each count value based on gammas
counted during a particular time bin. The count values may be adjusted up
or down to account for differences in the number of neutrons giving rise
to the gammas or different tools, and such adjustment shall not negate
the status as a "gamma count rate decay curve."

[0008] "Inelastic count rate" shall mean a gamma count rate during periods
of time when gammas created by inelastic collisions are the predominant
gammas created and/or counted (e.g., during a neutron burst period). The
minority presence of counted capture gammas shall not obviate a count
rate's status as an inelastic count rate.

[0009] "Capture count rate" shall mean a gamma count rate during periods
of time when gammas created by thermal neutron capture are the
predominant gammas created and/or counted (e.g., periods of time after
the neutron burst period). The minority presence of counted inelastic
gammas shall not obviate a count rate's status as a capture count rate.

[0012] FIG. 1 is a schematic partially cross-sectional view of a nuclear
logging system embodying principles of the present disclosure.

[0013] FIG. 2 is a schematic cross-sectional view of a logging tool which
may be used in accordance with the principles of this disclosure.

[0014] FIG. 3 is a plurality of graphs as a function of time
representatively illustrating how gamma arrivals are recorded and
characterized in a method embodying principles of this disclosure.

[0015] FIG. 4 illustrates graphs of fluid type indicative response values
for different fluid types as a function of porosity, the graphs being
representative of the response values for different pressures.

[0016] FIG. 5 is a flow chart representatively illustrating one embodiment
of the method in which one or more fluid types are determined in
accordance with the principles of this disclosure.

[0017]FIG. 6 is a schematic diagram of a computer system which may be
used in accordance with the principles of this disclosure.

DETAILED DESCRIPTION

[0018] The various embodiments were developed in the context of wireline
logging tools, and thus the description that follows is based on that
developmental context. However, the various systems and methods find
application not only in wireline logging tools, but also
measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools.

[0019] The various embodiments also find application in "slickline" tools,
in which the logging tool is placed downhole (e.g., as part of a drill
string, or as a standalone device) and the logging tool gathers data that
is stored in a memory within the device (i.e., not contemporaneously
transmitted to the surface). Once the tool is brought back to the
surface, the data is downloaded, some or all the processing takes place,
and the logging data is printed or otherwise displayed.

[0020] Thus, the developmental context (wireline conveyed logging tools)
shall not be construed as a limitation as to the applicability of the
various embodiments. Instead, the principles of this disclosure may be
incorporated into any types of well tools.

[0021] FIG. 1 illustrates a nuclear logging system 100 constructed in
accordance with a least some embodiments.

[0022] In particular, system 100 comprises a logging tool 10 placed within
a borehole 12 proximate to a formation 14 of interest. The borehole 12
may be cased, as depicted in FIG. 1, or it may be uncased or open hole in
an interval logged by the tool 10.

[0023] The tool 10 comprises a pressure vessel 16 within which various
subsystems of the tool 10 reside, and in the illustrative case of FIG. 1
the pressure vessel 16 is suspended within the borehole 12 by a cable 18.
Cable 18, in some embodiments a multi-conductor armored cable, not only
provides support for the pressure vessel 16, but also in these
embodiments communicatively couples the tool 10 to a surface telemetry
module 20 and a surface computer 22.

[0024] The tool 10 may be raised and lowered within the borehole 12 by way
of the cable 18, and the depth of the tool 10 within the borehole 12 may
be determined by depth measurement system 24 (illustrated as a depth
wheel). In some embodiments, the pressure vessel 16 may be covered with a
thermal neutron absorptive material 26 (the thickness of which is
exaggerated for clarity in the figure). However, in other embodiments the
material 26 may be only partially present or maybe omitted altogether.

[0025] FIG. 2 shows a simplified cross-sectional view of the logging tool
10 to illustrate the internal components in accordance with at least some
embodiments. In particular, FIG. 2 illustrates that the pressure vessel
16 houses various components, such as a telemetry module 200, borehole
shield 202, a plurality of gamma detectors 204 (in this illustrative case
three gamma detectors labeled 204A, 204B and 204C), computer system 206,
a neutron shield 208 and a neutron source 210.

[0026] While the gamma detectors 204 are shown above the neutron source
210, in other embodiments the gamma detectors may be below the neutron
source. Gamma detector 204C may be on the order of 12 inches (˜30.5
cm) from the neutron source. The gamma detector 204B may be on the order
of 24 inches (˜61 cm) from the neutron source 210. The gamma
detector 204A may be on the order of 32.5 to 36 inches from the neutron
source 210 (˜82.5-91.4 cm). Other spacings may be equivalently
used.

[0027] Neutron shield 202 may make the gamma detectors 204 receive more
favorably formation-sourced gammas (as opposed to borehole-sourced
gammas). The shield 202 may be a high density material (e.g.,
HEVIMET® available from General Electric Company of Fairfield,
Conn.). In other embodiments, alternate or additional shields may be
interposed between the detectors 204.

[0028] In some embodiments the neutron source 210 is a Deuterium/Tritium
neutron generator. However, any neutron source capable of producing
and/or releasing neutrons with sufficient energy (e.g., greater than 8
Mega-Electron Volt (MeV)) may equivalently be used.

[0029] The neutron source 210, under command from surface computer 22 in
the case of wireline tools, or computer system 206 within the tool in the
case of MWD, LWD or slickline tools, generates and/or releases energetic
neutrons. In order to reduce the eradiation of the gamma detectors 204
and other devices by energetic neutrons from the neutron source 210,
neutron shield 208 (e.g., HEVIMET®) separates the neutron source 210
from the gamma detectors 204.

[0030] Because of the speed of the energetic neutrons (e.g., 30,000
kilometers/second or more), and because of collisions of the neutrons
with atomic nuclei that change the direction of movement of the neutrons,
a neutron flux is created around the logging tool 10 that extends into
the formation 14. Neutrons generated and/or released by the source 210
interact with atoms by way of inelastic collisions and/or thermal
capture.

[0031] In the case of inelastic collisions, a neutron inelastically
collides with atomic nuclei, a gamma is created (an inelastic gamma), and
the energy of the neutron is reduced. The neutron may have many inelastic
collisions with the atomic nuclei, each time creating an inelastic gamma
and losing energy.

[0032] At least some of the gammas created by the inelastic collisions are
incident upon the gamma detectors 204. One or both of a) the arrival time
of a particular gamma, and b) its energy may be used to determine its
status as an inelastic gamma.

[0033] After one or more inelastic collisions (and corresponding loss of
energy) a neutron reaches an energy known as thermal energy (i.e., a
thermal neutron). At thermal energy a neutron can be captured by atomic
nuclei.

[0034] In a capture event, the capturing atomic nucleus enters an excited
state and the nucleus later transitions to a lower energy state by
release of energy in the form of a gamma (known as a thermal gamma). At
least some of the thermal gammas created by thermal capture are also
incident upon the gamma detectors 204.

[0035] One or both of a) the arrival time of a particular gamma, and b)
its energy may be used to determine its status as a capture gamma. Only
inelastic and thermal capture interactions produce gammas, however.

[0036] Still referring to FIG. 2, when operational the gamma detectors 204
detect arrival and energy of gammas. Referring to gamma detector 204A as
indicative of all the gamma detectors 204, a gamma detector comprises an
enclosure 212, and within the enclosure 212 resides; a crystal 216 (e.g.,
a three inch by four inch yttrium/gadolinium silicate scintillation
crystal); a photo multiplier tube 218 in operational relationship to the
crystal 216; and a processor 220 coupled to the photomultiplier tube 218.

[0037] As gammas are incident upon/within the crystal 216, the gammas
interact with the crystal 216 and flashes of light are emitted. Each
flash of light itself is indicative of an arrival of a gamma, and the
intensity of light is indicative of the energy of the gamma.

[0038] The output of the photomultiplier tube 218 is proportional to the
intensity of the light associated with each gamma arrival, and the
processor 220 quantifies the output as gamma energy and relays the
information to the surface computer 22 (FIG. 1) by way of the telemetry
module 200 in the case of a wireline tool, or to the computer system 206
within the tool in the case of MWD, LWD or slickline tools.

[0039] FIG. 3 shows a plurality of graphs as a function of corresponding
time in order to describe how the gamma arrivals are recorded and
characterized in accordance with at least some embodiments. In
particular, FIG. 3 shows a graph relating to activation of the neutron
source 210, as well as gamma count rates for the near detector 204C, the
far detector 204B, and the long detector 204A.

[0040] The graph with respect to the neutron source 210 is Boolean in the
sense that it shows when the neutron source is generating and/or
releasing neutrons (i.e., the burst period), and when the neutron source
is not. In particular, with respect to the neutron source graph, the
neutron source is generating and/or releasing neutrons during the
asserted state 300, and the neutron source is off during the remaining
time.

[0041] In accordance with the various embodiments, a single interrogation
(at a particular borehole depth) comprises activating the neutron source
for a predetermined amount of time (e.g., 80 microseconds) and counting
the number of gamma arrivals by at least one of the detectors during the
activation time of the neutron source and for a predetermined amount of
time after the source is turned off. In at least some embodiments, the
total amount of time for a single interrogation (i.e., a single firing of
the neutron source and the predetermined amount of time after the neutron
source is turned off) may span approximately 1250 microseconds (μs),
but other times may be equivalently used.

[0042] Still referring to FIG. 3, with respect to counting gamma arrivals
by the gamma detectors 204, the interrogation time is divided into a
plurality of time slots or time bins. With reference to the graph for the
long detector 204A as illustrative of all the gamma detectors, in some
embodiments the interrogation time is divided into 61 total time bins.

[0043] In accordance with at least some embodiments, the first 32 time
bins each span 10 ps, the next 16 time bins each span 20 μs, and the
remaining time bins each span 50 μs. Other numbers of time bins, and
different time bin lengths, may be equivalently used.

[0044] Each gamma that arrives within a particular time bin increases the
count value of gammas within that time bin. While in some embodiments the
actual arrival time of the gammas within the time bin may be discarded,
in other embodiments the actual arrival may be retained and used for
other purposes.

[0045] Starting with time bin 0, the gamma detector counts the gamma
arrivals and increases the count value for the particular time bin for
each gamma arrival. Once the time period for the time bin expires, the
system starts counting anew the arrivals of gammas within the next time
bin until count values for all illustrative 61 time bins have been
obtained.

[0046] In some cases, the system starts immediately again by activating
the neutron source and counting further time bins. However, the count
values within each time bin (for a particular borehole depth) are
recorded either by way of the surface computer 22 in the case of wireline
tools, or by the computer system 206 within the tool in the case of MWD,
LWD or slickline tools.

[0047] Illustrative count values for each time bin are shown in FIG. 3 as
dots in the center of each time bin. The count value for each time bin is
represented by the height of the dot above the x-axis (i.e., the y-axis
value). Taking all the count values for a particular detector together,
the dots may be connected by an imaginary line (shown in dashed form in
FIG. 3) to form a mathematical curve illustrative of the number of gamma
arrivals as a function of time detected by the particular gamma detector.

[0048] In accordance with the various embodiments, the plurality of count
values is referred to as a gamma count rate decay curve. All the curves
taken together (the curve for each gamma detector) may be referred to as
full-set decay curves.

[0049] Because of the physics of the combined logging tool and surrounding
formation, within certain time periods certain types of gammas are more
likely to be created, and thus more likely to be counted by the one or
more active gamma detectors 204. For example, during the period of time
within which the neutron source 210 is activated (as indicated by line
300), the energy of neutrons created and/or released leads predominantly
to creation of inelastic gammas.

[0050] The period of time in the gamma count rate decay curves where the
gammas are predominantly inelastic gammas is illustrated by time period
304. Thus, gammas counted during some or all of the time period 304 may
be considered inelastic gammas.

[0051] Some capture gammas may be detected during the time period 304, and
in some embodiments the minority presence of capture gammas may be
ignored. In yet still other embodiments, because capture gammas are
distinguishable from inelastic gammas based on energy, the portion of the
count rate during time period 304 attributable to capture gammas may be
removed algorithmically.

[0052] Similarly, after the neutron source 210 is no longer activated, the
average energy of the neutrons that make up the neutron flux around the
tool 10 decreases, and the lower energy of the neutrons leads
predominantly to creation of capture gammas. The period of time in the
gamma count rate decay curves where the gammas are predominantly capture
gammas is illustrated by time period 306.

[0053] Thus, gammas counted during some or all of the time period 306 may
be considered capture gammas. Some inelastic gammas may be detected
during the time period 306, and in some embodiments the minority presence
of inelastic gammas may be ignored. In yet still other embodiments,
because inelastic gammas are distinguishable from capture gammas based on
energy, the portion of the count rate during time period 306 attributable
to inelastic gammas may be removed algorithmically.

[0054] We have found that a gamma count rate decay curve from a single
gamma detector may be used to determine a value indicative of fluid type
in the formation 14 at the particular borehole depth for which the gamma
count rate decay curve is determined. More particularly still, we have
found that a relationship between the inelastic count rate and the
capture count rate of a gamma count rate decay curve can be used to
derive a fluid type indicative response value (FTIRV) which is indicative
of fluid type (and more particularly, of gas type in certain
embodiments).

[0055] Consider, as an example, a single gamma count rate decay curve,
such as the long detector 204A gamma count rate decay curve of FIG. 3. In
accordance with the various embodiments, the response value may be a
ratio of the inelastic count rate to the capture count rate of the gamma
count rate decay curve.

[0056] The inelastic count rate may be the summed count rate from one or
more of the time bins within time period 304. In accordance with some
embodiments, the count rates from all the time bins within time period
304 may be summed and used as the inelastic count rate.

[0057] The capture count rate may be the summed count rate from one or
more of the time bins within time period 306. In accordance with some
embodiments, the count rates from time bins within time period 306 that
span 100 μs to 1000 μs after the deactivation of the neutron source
210 may be used.

[0058] In some embodiments, the ratio is the inelastic count rate divided
by the capture count rate, and in other embodiments the ratio is the
capture count rate divided by the inelastic count rate. Using the ratio,
a fluid type in the surrounding formation 14 may be determined based on
borehole 12 size, drilling fluid type, casing size (if present), pressure
and porosity of the surrounding formation.

[0059] We have also found that gamma count rate decay curves from multiple
gamma detectors may be used to determine a value indicative of fluid type
in the formation 14 at the particular borehole depth for which the gamma
count rate decay curves are determined. More particularly still, we have
found that a relationship between the inelastic count rates of gamma
count rate decay curves for respective different gamma detectors, and/or
a relationship between the capture count rates of gamma count rate decay
curves for respective different gamma detectors, can be used to derive a
response value which is indicative of fluid type, or more particularly,
of gas type.

[0060] Consider, as an example, multiple gamma count rate decay curves,
such as the long detector 204A gamma count rate decay curve, the far
detector 204B gamma count rate decay curve and the near detector 204C
gamma count rate decay curve of FIG. 3. In accordance with various
embodiments, the response value may be a ratio of the inelastic count
rate of one of these curves to the inelastic count rate of another of the
curves. In other embodiments, the response value may be a ratio of the
capture count rate of one of these curves to the capture count rate of
another of the curves.

[0061] In further embodiments, the response value may be a mathematical
combination of any of the ratios discussed above (e.g., the ratio of
inelastic and capture count rates for a single detector, the ratio of
inelastic count rates for multiple detectors, and the ratio of capture
count rates for multiple detectors). Thus, it should be understood that
the response value may be calculated in any manner, according to any
appropriate algorithm, in keeping with the principles of this disclosure.

[0062] Indeed, it is not necessary for the response value to be a ratio at
all. The response value could instead be, for example, an inelastic
and/or capture count rate itself, sums of such count rates, differences
between such count rates, products of such count rates, or due to any
appropriate algorithm applied to the count rates.

[0063] FIG. 4 shows an illustrative relationship between a range of
possible response values, and a range of possible porosities of the
formation, for a particular formation pressure. Plotted on the graph 400
of FIG. 4 are four different curves: 402 indicating a fluid type of oil,
404A indicating a fluid type of wet gas, 406A indicating a fluid type of
dry gas, and 408 indicating a substantial lack of fluid (i.e., a depleted
formation).

[0064] Note that, for a given porosity and a determined response value,
one of the four fluid types will be indicated. For example, point 410 on
the graph 400 (which corresponds to a porosity of 10 and a response value
of 0.13) would indicate that the fluid type in the formation is dry gas.

[0065] In situations where a point corresponding to a given porosity and a
determined response value does not fall on one of the curves 402-408,
then the position of the point can provide an indication of the relative
volumes of fluid types in the formation via interpolation. For example,
point 412 on the graph may indicate that about 3/4 of the volume of gas
in the formation is wet gas and about 1/4 of the volume is dry gas, since
the point 412 is positioned a distance about three times as far from the
dry gas curve 406A as from the wet gas curve 404A. The interpolation may
be a linear interpolation, as in the example above, or the interpolation
may be nonlinear, based on a simple or complex model, etc.

[0066] The graph 400 also depicts the dry and wet gas curves at a higher
formation pressure (the oil and depleted curves do not change
significantly with pressure). In the graph 400, curve 404B indicates a
fluid type of wet gas at increased formation pressure, and curve 406B
indicates a fluid type of dry gas at the increased formation pressure.

[0067] The curves 404B and 406B are very similar in form to the curves
404A and 406A. However, note that the wet gas and dry gas curves 404B,
406B are shifted upward somewhat in the graph 400 as compared to curves
404A, 406A of FIG. 4A.

[0068] This demonstrates the effect of pressure on the density of the gas
and, correspondingly, on the response value. Although the graph 400 is
depicted in FIG. 4 for only two formation pressures, it will be
appreciated that a graph could be produced for any given pressure. In
addition, although only oil, wet gas and dry gas fluid types curves are
shown in the graph 400, any other fluid type (e.g., fresh water, saline
water, etc.) could be shown, if desired.

[0069] In practice, the formation pressure should be known (e.g., from
concurrent measurements or previous logs), and so the various curves to
be used in a particular situation will also be known. The curves for oil,
wet gas, dry gas and/or other fluid types may be stored in a database
(such as in a look-up table, etc.), or the curves may be represented as
mathematical functions, with formation pressure being one of the
variables used to calculate the curves. For example, the fluid type
curves could be normalized for pressure.

[0070] Thus, it will be readily appreciated that, if the porosity,
response value and pressure are known, the fluid type can also be known,
using the principles of this disclosure. Accordingly, an operator can
determine whether production of the fluid should be initiated or
continued, the effectiveness of conformance operations, and other
possible useful information. This information can be obtained even if the
wellbore 12 is cased and cemented.

[0071] The various embodiments discussed to this point have been described
as if that the gamma count rate decay curves are obtained by a logging
tool contemporaneously with calculating the response value and
determining the fluid type(s) in the formation 14. However, in other
embodiments calculating the response value and determining the fluid
type(s) may take place non-contemporaneously with a logging tool
obtaining the gamma count rate decay curves. Thus, the step of
determining fluid type(s) may be performed using historical logging data
gathered hours, days, weeks or months in advance.

[0072] The logging tool 10 of FIG. 2 illustrates three gamma detectors
204. However, the various embodiments of calculating the response and
determining the fluid type may utilize the gamma count rate decay curves
from a single gamma detector.

[0074] However, as the porosity of the formation surrounding the borehole
increases, better gamma count rate decay curves for determining fluid
type may be obtained from the closer spaced gamma detectors 204.

[0075] Thus, in some embodiments, the gamma detector 204 used to read the
gamma count rate decay curve for determination of fluid type is selected
based on a value indicative of porosity. For example, if the porosity of
the formation is known prior to running the tool 10 in the borehole 12
(i.e., the porosity is determined non-contemporaneously with obtaining
the gamma count rate decay curves and held in a database), then a gamma
detector 204 may be selected based on the previously determined porosity.

[0076] In other embodiments, although only one gamma detector 204 is
needed for purposes of determining response values indicative of fluid
type, two or more of the gamma detectors 204 may nevertheless be
operational for measuring other formation parameters of interest, such as
a value indicative of porosity. In embodiments where the value indicative
of porosity (e.g., ratio of the capture count rate for two detectors) is
measured contemporaneously with obtaining the gamma count rate decay
curves, the gamma detector 204 used for determining the response value
indicative of fluid type may be selected based on the contemporaneously
determined value indicative of porosity. Furthermore, over the course of
a single logging run, multiple gamma detectors 204 may be used, one at a
time, for determining the response value indicative of fluid type based
on the values indicative of porosity of the formation at different
borehole depths.

[0077] FIG. 5 illustrates a method 500 in accordance with at least some
embodiments, where the method may be implemented, at least in part, by
the computer system 22, the computer system 206 within the logging tool,
or any other general purpose or special purpose computer system. In
particular, the method 500 may be implemented by a suitable program
stored on a computer-readable storage media.

[0078] The method 500 starts at block 502 and proceeds to obtaining at
least one gamma decay curve for a particular borehole depth (block 504).
In some embodiments, the obtaining is by operation of the nuclear logging
tool contemporaneously with the further steps of the illustrative method,
while in other embodiments the obtaining is from a database of gamma
count rates generated based on operation of the nuclear logging tool
non-contemporaneously contemporaneously with the further steps of the
illustrative method.

[0079] Regardless of the precise mechanism of obtaining the gamma count
rates, the illustrative method 500 then moves to calculating a fluid type
indicative response value (FTIRV) at block 506. In some embodiments, the
FTIRV is the inelastic count rate divided by the capture count rate, but
in other embodiments the ratio is the capture count rate divided by the
inelastic count, using a single gamma detector. In other embodiments, the
FTIRV is a ratio of inelastic count rates or capture count rates from
multiple gamma detectors.

[0080] In further embodiments, the FTIRV may be a mathematical combination
of any of the ratios discussed above (e.g., the ratio of inelastic and
capture count rates for a single detector, the ratio of inelastic count
rates for multiple detectors, and the ratio of capture count rates for
multiple detectors). The FTIRV may be calculated in any manner, according
to any appropriate algorithm, in keeping with the principles of this
disclosure.

[0081] Next, the method 500 moves to a determination of one or more fluid
types based on the FTIRV at the particular borehole depth (block 508).
The determination of the fluid type(s) is preferably based on porosity of
the formation surrounding the borehole at the particular borehole depth,
as well as pressure in the formation at that depth, such as by a
relationship similar to that shown in illustrative FIGS. 4A & B.

[0082] While one value indicative of fluid type at a particular borehole
depth may be useful in some circumstances, in some cases the gamma decay
curve obtaining (block 504), FTIRV calculating (block 506) and fluid type
determining (block 508) may be repeated for a plurality of borehole
depths (block 510). Thus, a determination of how the fluid type(s) in the
formation 14 vary along the depth of the borehole 12 can be obtained.

[0083] A display of the fluid type(s) is produced (block 512), and the
illustrative method ends (block 514). The displaying may take many forms.
In some cases, a paper plot with fluid type(s) indicated along the depth
of the borehole may be created, and in yet other cases the display may be
by way of a graphical display device (such as a computer monitor) coupled
to a computer system. Other types of displays may be used in accordance
with the principles of this disclosure.

[0084]FIG. 6 illustrates in greater detail a computer system 600, which
is illustrative of both the surface computer system 22 and the computer
system 206 within the logging tool 10, either or both of which may be
used. Thus, the computer system 600 described with respect to FIG. 6
could be proximate to the borehole during the time period in which the
tool 10 is within the borehole, the computer system 600 could be located
at the central office of the oilfield service company, or the computer
system 600 could be within the logging tool 10 (such as for LWD, MWD or
slickline tools).

[0085] The computer system 600 comprises a processor 602, and the
processor couples to a main memory 604 by way of a bridge device 608.
Moreover, the processor 602 may couple to a long term storage device 610
(e.g., a hard drive or a programmable memory device) by way of the bridge
device 608.

[0086] Programs executable by the processor 602 may be stored on the
storage device 610, and accessed when needed by the processor 602. The
program stored on the storage device 610 may comprise programs to
implement the various embodiments of the present specification, including
programs to implement selecting a gamma detector to use in the fluid type
determination, calculating the fluid type indicative response value,
determining the fluid type(s), and producing a display of the fluid
type(s).

[0087] In some cases, the programs are copied from the storage device 610
to the main memory 604, and the programs are executed from the main
memory 604. Thus, both the main memory 604 and storage device 610 are
considered computer-readable storage mediums.

[0088] The response values indicative of fluid type, as well as the
determined fluid type(s), produced by the computer system 610 may be sent
to a plotter that creates a paper log, and/or the values may be sent to a
display device which may make a representation of the log for viewing by
a geologist or other person skilled in the art of interpreting such logs.

[0089] From the description provided herein, those skilled in the art are
readily able to combine software created as described with appropriate
general-purpose or special-purpose computer hardware to create a computer
system and/or computer sub-components in accordance with the various
embodiments, to create a computer system and/or computer sub-components
for carrying out the methods of the various embodiments and/or to create
a computer-readable media that stores a software program to implement the
method aspects of the various embodiments.

[0090] The above disclosure provides to the art many advancements and
improvements, including a method 500 which includes obtaining gamma count
rates at a particular borehole depth; calculating a fluid type indicative
response value for the particular borehole depth; determining at least
one fluid type based on the response value for the particular borehole
depth; and producing a display of the at least one fluid type
corresponding to the particular borehole depth.

[0091] Producing the display may include producing a paper plot of the at
least one fluid type corresponding to the particular borehole depth.

[0093] Calculating the fluid type indicative response value may include
calculating a ratio of inelastic and capture count rates from a single
gamma detector 204, and/or computing a mathematical function of count
rates from a single gamma detector 204.

[0095] Obtaining the at least one gamma decay curve may include operating
a neutron source 210 within a borehole 12. Operating the neutron source
210 may include operating the neutron source 210 within a cased portion
of the borehole 12.

[0096] Determining the at least one fluid type may include determining the
at least one fluid type further based on a porosity of a formation 14 at
the particular borehole depth, and further based on a pressure in the
formation 14 at the particular borehole depth.

[0097] Also provided by the above disclosure is a system 100 which
includes a downhole tool 10 comprising a neutron source 210 and at least
one gamma detector 204. Gamma count rates are produced due to gamma
arrivals at the at least one gamma detector 204. A processor 602 is
coupled to a memory 604. The memory 604 stores a program that, when
executed by the processor 602, causes the processor 602 to: calculate a
fluid type indicative response value for a particular borehole depth
based on the gamma count rates; and determine at least one fluid type
based on the response value for the particular borehole depth.

[0098] The program may cause the processor 602 to calculate the fluid type
indicative response value based on the gamma count rates produced due to
the gamma arrivals at multiple gamma detectors 204 of the downhole tool
10.

[0099] The program may cause the processor 602 to calculate the fluid type
indicative response value as a ratio of inelastic count rates and capture
count rates due to the gamma arrivals at one gamma detector 204.

[0100] The program may cause the processor 602 to calculate the fluid type
indicative response value as a mathematical function of the count rates
due to the gamma arrivals at one gamma detector 204.

[0101] The program may cause the processor 602 to calculate the fluid type
indicative response value as a ratio of inelastic count rates due to the
gamma arrivals at multiple gamma detectors 204.

[0102] The program may cause the processor 602 to calculate the fluid type
indicative response value as a ratio of capture count rates due to the
gamma arrivals at multiple gamma detectors 204.

[0103] The program may cause the processor 602 to calculate the fluid type
indicative response value as a mathematical function of the count rates
due to the gamma arrivals at multiple gamma detectors 204.

[0104] The neutron source 210 may be positioned within a cased portion of
a borehole 12.

[0105] The program may cause the processor 602 to determine the at least
one fluid type further based on a porosity of a formation 14 at the
particular borehole depth, and further based on a pressure in the
formation 14 at the particular borehole depth.

[0106] The above disclosure also describes a computer-readable storage
media 604 storing a program that, when executed by a processor 602,
causes the processor 602 to:

[0107] calculate a fluid type indicative response value for a particular
borehole depth based on the gamma count rates; and determine at least one
fluid type based on the response value for the particular borehole depth.

[0108] The above description is meant to be illustrative of the principles
and various embodiments of the present disclosure. Numerous variations
and modifications will become apparent to those skilled in the art once
the above disclosure is fully appreciated.

[0109] For example, in some embodiments, the counts associated with
capture gammas are removed from the inelastic count rate, and counts
associated with inelastic gammas are removed from the capture count rate,
prior to calculating the FTIRV. In other cases, however, the presence of
counts of capture gammas in the inelastic count rate, and likewise the
presence of inelastic gammas in the capture count, is ignored for
purposes of calculating the FTIRV.

[0110] Furthermore, preprocessing of the data may take place, such as
dead-time correction and environmental correction, without affecting
scope of this specification. It is intended that the appended claims be
interpreted to embrace all such variations and modifications.

[0111] It is to be understood that the various embodiments of the present
disclosure described herein may be utilized in various configurations,
without departing from the principles of the present disclosure. The
embodiments are described merely as examples of useful applications of
the principles of the disclosure, which is not limited to any specific
details of these embodiments.

[0112] Of course, a person skilled in the art would, upon a careful
consideration of the above description of representative embodiments of
the disclosure, readily appreciate that many modifications, additions,
substitutions, deletions, and other changes may be made to the specific
embodiments, and such changes are contemplated by the principles of the
present disclosure. Accordingly, the foregoing detailed description is to
be clearly understood as being given by way of illustration and example
only, the spirit and scope of the present invention being limited solely
by the appended claims and their equivalents.